Substation load distribution monitor system

ABSTRACT

The monitoring and control system of the present invention provides a distributed intelligence, data acquisition and control system which collects and analyzes large amounts of data representing power usage from a power distribution substation. The system also provides the capability of various control functions for the substation. The system provides communications capabilities between local devices and also with a remote computer. The system provides real time monitoring of power usage and real time control of various functions in the substation.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to improvements in monitoring andcontrolling substation power distribution. Specifically, the inventioninvolves a method and apparatus for automatically monitoring substationpower distribution and usage and transmitting the information to aremote location in order to provide real time, improved-accuracymonitoring of consumer loads and to control a remote power distributionsubstation from a remote location.

2. Description of the Related Art

At each power substation, there are generally transmission anddistribution circuits, transformers, circuit breakers, capacitor banks,and other electrical equipment (hereinafter "power equipment") whichdeliver electrical power. The various pieces of electrical equipment,including the circuits and transformers, are protected for overload andfault conditions by monitoring the current in each phase of theequipment. The normal method of monitoring this current is by using acurrent transformer. A current transformer transforms the primarycurrent (normally in the range of 100 to 3000 amps) to a secondarycurrent in the range of 5 amps. The secondary current is then monitoredvia protection equipment, and upon detection of an overload or fault,the protection equipment will trip (open) the appropriate breakers toterminate the fault.

Because the current transformer has a known primary to secondary ratio,the current transformer can also be considered as a current sensor. Thiscurrent sensor is used via a transducer in many substations to provide aDC signal which is representative of the primary current. In mostapplications today, the transducer is installed by inserting it inseries with the secondary of each current transformer which is to bemonitored.

Another possibility for monitoring the secondary current is to pass thesecondary lead of the current transformer through a solid core currenttransformer, and measuring the output of the solid core transformer.

If the substation is being retrofitted for collection of this currentdata, the secondary lead of the current transformer must be cut andwired through the transducer, or at least disconnected and passedthrough a solid core current transformer.

Even though the secondary lead of the protection circuit currenttransformer only carries approximately 5 amps, if this wire is severed,the voltage across the open ends will increase to whatever voltage isnecessary to provide a current in the secondary lead of the currenttransformer corresponding to the current flowing in the primary side ofthe current transformer. This voltage could become very high, creating adangerous condition, including developing an arc within the currenttransformer. Therefore, in order to install a transducer in the currenttransformer secondary wire safely, the entire substation, or a portionof the substation, is de-energized so that the current transformersecondary wire may be cut and the transducer installed without seriousdanger.

This process is very time consuming and expensive. For instance, if asubstation had ten circuits, each with three phases, it would takeapproximately 40 man hours to install the transducers in all of theprotection circuit lines.

Moreover, in order to repair the transducer, it is often necessary toshut down the substation, or at least a portion of the substation.

Another disadvantage to present systems is that the meters connected tothe transducers are located at the substations. Therefore, in order tomonitor the power usage through the substation, a person reads themeters and records the measurements. This does not provide real timeinformation. Thus, this type of monitoring generally results inproviding more power through a station to handle the maximum expectedload than is absolutely necessary.

Systems, such as those disclosed in U.S. Pat. Nos. 4,396,915 and4,315,251, disclose automatic meter reading and control systems. Thesystems disclosed automatically read meters at the point of use byindividual consumers and transmit the data to central location. Thesesystems, if applied to the power substation contexts, would provide realtime data; however, these systems would not solve the problem of cuttinginto the protection circuit at a substation to install the transducerswhich operate the meters.

SUMMARY OF THE INVENTION

Applicant recognized that this conventional method of monitoring couldbe improved and that it would be advantageous if installation of amonitoring system did not require de-energizing the electrical equipmentassociated with the primary of the current transformer.

Applicant also recognized that if these substations were monitoredefficiently in real time with accurate information transmitted to acentral location, then the utility company could more efficiently useexisting substations to their capacity and thereby reduce the number ofsubstations required for power distribution.

Therefore, the present invention involves a distributed data acquisitionand control system to meet the functional requirements of powerdistribution system substation monitoring and control. In particular,the invention involves collecting and analyzing power transmission anddistribution data representative of power usage at a substation andproviding this data to a remotely located office. The system, insummary, provides data including the line voltage, line current, watts,volt amperes reactive (VARs), power factor (PF) and other importantparameters as further explained herein. The applicant recognized thatthis monitoring could be accomplished efficiently without cutting intothe protection circuit, or taking the substation off-line. The presentinvention thus simplifies installation and minimizes the cost, yetprovides accurate information.

The information collected using the present invention is transmitted tothe utility company's remote office, in one embodiment, for real timedata monitoring of power usage through the substation.

One aspect of the present invention involves a power monitoring systemfor use in power distribution substations with power equipment carryingvoltage and current to distribute electrical power. The power equipmentgenerally has an associated protection circuit with a current flowingwhich is stepped down from, but proportionally corresponds to, thecurrent flowing through the power equipment. The system comprises atleast one system controller, wherein the system controller is amicroprocessor based controller with a respective power converter whichsteps down the voltages on the power equipment. The system furthercomprises at least one data acquisition unit in communication with thesystem controller, wherein the data unit comprises a microprocessorbased controller, an analog to digital converter and a memory.Additionally, the system comprises at least one clamp-on, split-corecurrent transformer detachably mounted on one leg of the protectioncircuit, and the current transformer provides current, stepped downfrom, but proportional to, the instantaneous current flowing in thepower equipment. Moreover, the current provided by the currenttransformer is converted by the analog to digital converter into digitalform for further processing by the data unit and the system controller.

In one embodiment, the system controller communicates with a remotecomputer over a communications link.

Another aspect of the present invention involves a method of monitoringpower equipment carrying a voltage and a current, wherein the powerequipment also has associated protection circuits carrying a currentwhich is stepped down from, but proportional to, the current flowing inthe power equipment. In summary, this aspect of the present inventioninvolves providing at least one system controller, providing at leastone data acquisition controller in communication with the systemcontroller, stepping down the voltage in the power equipment, anddetachably mounting a split-core current transformer on one leg of theprotection circuit. The split-core current transformer provides acurrent, stepped down from, but proportional to, the current flowing inthe power equipment. A representation of the current provided by thecurrent transformer is sampled and converted into digital form forfurther processing by the system controller and the data acquisitionunit. The stepped-down power equipment voltage is also sampled andconverted into digital form. The relative phase angle between thesampled current and the sampled voltages, the power, the power factorand volt amperes distributed by the power equipment are then calculated.Finally, the calculations are transmitted to a remote computer.

This system provides numerous advantages over existing systems. Aspreviously explained, to install or repair conventional monitoringsystems without serious danger, all or a portion of the substation isde-energized. In the present invention, a split-core current transformeris simply clamped onto the secondary lead of the protection circuit, andthe resulting current from the split-core transformer is very low (inthe milliamp range). Therefore, installation is very quick and easy. Thesimple installation results in substantial cost savings when compared toinstallation of conventional monitor and control systems forsubstations.

Moreover, even though split-core transformers are often used to monitorcurrent, the present invention provides a system which is highlyaccurate from sample to sample, even though the monitored current isstepped down from an initially high value (100 to 3000 amps) to themilliamp range. Thus, the utility company receives data which accuratelyrepresents the power usage through the power equipment at thesubstation.

Finally, the present invention also provides a system in which repairsare easy. Not only can the split-core transformer be easily removed orreplaced without cutting into the protection circuit, data acquisitionunits which sample the stepped down voltage and current in thesubstation are daisy chained together. Thus, if a data acquisition unitneeds repair, it can be removed from service by simply disconnecting itfrom the daisy-chain. The daisy-chain is then connected together withoutthe data acquisition unit which needs service. The remainder of thesystem continues to function as normal.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a block diagram of the power monitoring system of the presentinvention.

FIG. 2 is a functional block diagram of an exemplary remote data unit(RDU).

FIGS. 3 and 3a depict a clamp-on current transformer.

FIG. 4 is a block diagram of an exemplary substation remote terminalunit (RTU).

FIG. 5A and FIG. 5B are exemplary flow charts for firmware of the RDU.

FIG. 6 is an exemplary flow chart for firmware of the RTU.

FIG. 7 and FIG. 7A are block diagrams showing an embodiment with RDUsoperating remote to the main RDU/RTU combinational system.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

FIG. 1 depicts the overall system block diagram of the presentinvention. The system comprises, a plurality of remote data units (RDUs)100, 100A, 100B, 100C, which are chained together with a daisy chaincable 102 which connects the remote data units to a remote terminal unit(RTU) 104. The four RDUs 100-100C are simply shown for illustrationpurposes. The system may comprise more or fewer RDUs. In the presentembodiment, the RTU 104 communicates with a remote computer such as thehost computer 110 over a communications link 106. The communicationslink 106 may comprise any communications system such as a radiocommunications link, a modem/telephone line link, a fiber optic link orany other communications link.

The Remote Data Units

A functional block diagram of an individual remote data unit (RDU) 100is shown in FIG. 2. Further references to RDU(s) 100 includes any of theRDUs 100-100C. The RDU comprises a microprocessor based controller withcontrol and data acquisition capabilities. The RDU 100 samples scaleddown analog voltage and current signals proportionally corresponding tovalues in power equipment, and determines values for the power factor,watts, volt amperes reactive (vars), voltage and amperes for therespective power equipment.

The RDU 100 shown in FIG. 2 illustrates the structure for each of theRDUs 100, 100A, 100B, and 100C of FIG. 1. The RDU 100 comprises a powersupply 130, which provides +5 and +/-15 volts DC for other elements inthe RDU 100, a multi-channel analog to digital (A/D) converter 150, amemory 160, a serial interface 172 and a parallel interface 170. Amicroprocessor based central processing unit (CPU) 200 provides controlfor the RDU 100, and a digital input/output (I/O) interface 190 providesfurther monitoring and control capabilities for the substation on thedigital input lines 114 and the digital output lines 116. Split-core,clamp-on current transformers (CTs) 140A, 140B, 140C, provide analogcurrent sense signals on lines 142A, 142B, 142C to the A-D converter150. Further references to CT(s) 140 includes any of the CTs 100A-140Cin the system. An RDU address selector 202 comprising an eight-positiondual-in-line package (DIP) switch connected to the parallel interface170 indicates the address of the RDU 100 within the daisy-chained RDUs100, 100A, 100B, and 100C (FIG. 1). The DIP switch address selector 202also provides further configuration information for the RDU 100 asdescribed herein.

The daisy chain cable 102 advantageously comprises an 18-twisted paircable with overall shield rated at 600 volts. The daisy chain cable 102carries signals for the RDUs 100-100C on a 24-volt DC power input sourcesignal lines 120, low voltage (e.g., six volts) AC sense signals fromthe RTU 104 on signal lines 122, (advantageously, the RTU 104 transformsthe power equipment voltages to stepped-down sense signalsrepresentative of the AC line voltage), and serial communicationsinterface signal lines 124 for communications over, advantageously, aconventional RS-485 multidrop link. The daisy chain cable 102 isconnected to each RDU 100 via a quick disconnect female connector 143and leaves the RDU 100 via a similar male connector 146. The RDU hascorresponding male and female connectors 142 and 144. Advantageously,these connectors comprise D-subminiature, 37-pin male and femaleconnectors available from Cinch Corp. of Oak Grove Village, Ill. Thisdaisy chain approach allows each individual RDU 100 to be removed fromservice for testing or repair without impacting on the operation of theremainder of the system or the pow]r substation. Each RDU 100 can beremoved by simply powering down the control system and disconnecting themale and female connectors 146 and 143 respectively from the RDU 100 andreconnecting the respective female and male connectors 143 and 146without the RDU 100 which has been removed.

The 24-volt DC power from the RTU 104 on line 120 serves as a powersource for he power supply 130 which comprises conventional +/-15 voltand +5 volt power supplies. The power supply 130 distributes powerthroughout the RDU 100. A number of AC sense signals also enter the RDU100 on signal lines 122. For instance, if there is one three-phase powertransmission or distribution line in the substation, then the signallines 122 carry three low voltage AC sense signals, one corresponding toeach phase of the power equipment.

Advantageously, all of the power and voltage sense signals are metaloxide varistor (MOV) protected.

The A/D converter 150 accepts analog inputs from multiple channels. Inthe present embodiment, the A/D converter 150 accepts inputs fromsixteen-channels. The low voltage sense signals from the RTU 100 enterthe A/D converter 150 via signal lines 122. The A/D converter 150converts the sense signals to digital form upon request by the CPU 200.The digitized values are read by the CPU 200 via a conventional data bus203 connecting the A/D converter 150 to the CPU 200. An INTEL 80C88microprocessor controls the CPU 200 operations. The CPU 200 alsoincludes a real time clock (not shown). In the present embodiment, thememory 160, connected to the CPU 200 via the conventional data bus 203,comprises 16K bytes of EPROM (erasable programmable read only memory),and up to 256K bytes of CMOS (complementary metal oxide semiconductor)static memory. A CPU clock (not shown) generates 100 millisecondinterrupts for the CPU 200. These components are well understood in theart.

Each RDU 100, although structurally identical, is unique in the daisychain after it is configured with an associated address. The DIP switch202 address is configured by setting five of the switches to represent afive-bit address for the corresponding RDU 100. The address selector202, is read by the CPU 200 from the parallel interface 170. The CPU 200stores this five-bit address in the CMOS static memory.

The clamp-on CTs 140, as depicted in FIG. 3 and 3a, comprise a housingconstructed of plastic or other composite material, and a split-corecurrent transformer within the housing. Advantageously, the housing isgenerally rectangular in shape and approximately 1.2 inches wide, 1.5inches high and about 3.5 inches long. The housing has a detachable baseplate 214, a main body portion 216, and two connectors depicted in thisembodiment as screws 224, 226 each with corresponding pressure plates228 and 230. One of the connectors is marked with a polarity marking 231which indicates the positive terminal of the CT 140. The main bodyportion 216 is approximately 2.5 inches long, 1.4 inches high, and 1.2inches wide. At the base of the main body portion, two extendingportions 234 and 236 provide a base-plate mounting surface.

These extending portions 234 and 236 extend from the base of the mainbody portion 216 such that the overall length of the main body portion216 plus the extending portions 234 and 236 is approximately 3.5 inches.Each extending portion 234 236 has an aperture 240 and 241 adapted toreceive screws 242 and 243, respectively which are preferably positionedthrough the base plate 214. Each of the screws 242 and 243 has acorresponding thumb nut 244 and 245 respectively.

Each main body portion 216 also has semi-circular channel 232 defined atthe base, and extending across the width, of the main body portion 216.As seen in FIG. 3a, the main body portion 216 houses the secondary sideof a split-core current transformer 246 with a dynamic range of 0-10amps and an overall repeatable accuracy of better than 1% over theoperating range in the present invention. The channel 232 is formedabout the core of the secondary of the current transformer.Advantageously, when operational, the split-core current transformersteps down the current by a factor ranging from approximately 10,000:1to 2,000:1. Other scaling factors are also suitable depending upon thesignals desired from the CTs for particular applications.Advantageously, the current is stepped down sufficiently in thesplit-core transformer 246 so as keep the current low enough to avoidoverloading the protection circuit current transformer. However, evenwhen the current is stepped down into the 0-0.5 mA operating range forthe output of the split-core current transformer, the 1% repeatableaccuracy is maintained.

A cover 247 is placed within the main body portion to protect thetransformer 246 as depicted in FIG. 3.

The detachable base plate 214 is planar and is detachably mounted to thebase of the main body portion 216. Advantageously, the detachable baseplate is approximately 5 inches long, 0.375 inches thick, and 1.2 incheswide. The base plate 214 has, advantageously, a planar conductive plate238 embedded within and along the detachable base plate 214 in a cavityin the base plate 214 adapted to receive the conductive plate 238. In apreferred embodiment, the conductive plate 238 is mounted with a spring239 positioned in the cavity in the base plate 214 between theconductive plate 238 and the base plate 214 The conductive plate 238 isheld in place with pins 248 which pass through the conductive plate 238at each end of the conductive plate 238. In the preferred embodiment,the face of conductive plate protrudes above the surface of the baseplate 214 when the base plate is not attached to the main body portion216. With this configuration, the conductive plate maintains a snug fitto complete the split-core transformer 246 when the base plate 214 isattached to the main body portion 216 of the housing. Moreover, in apreferred embodiment, an insulating layer 249 of non-conductive materialis positioned around the edge of the conductive plate 238 within thecavity in the base plate 214. When the base plate 214 is attached to themain body 216 of the housing, the conductive plate 238 completes thecore of the split-core current transformer 140. The base plate 214 alsohas apertures which may be threaded and adapted to receive the screws242 and 243 respectively to attach the base plate 214 to the main bodyportion 216. When the base plate 214 is attached to the main bodyportion 216, it extends beyond each extending portion 234, 236 so thatthe base plate 214 can be independently attached to a mounting surfaceby the use of the apertures 250 and 252.

Advantageously, the current sense signals from the CTs 140A-140C areprotected with a back-to-back diode configuration well understood in theart. For instance, in a preferred embodiment, a conventional transientovervoltage suppressor (not shown), such as a Motorola IN6386 ZenerOvervoltage Transient Suppressor, is positioned within the housing 214and connected between the two connectors.

A wire passing through the aperture 232 functions as the primary for thecurrent transformer when the base plate 214 is attached to the main bodyportion 216. Exemplary split-core current transformers suitable for usewithin the housing are manufactured by AEMC Instruments corp., Boston,Mass. (CT parts kit #1031.03).

As described, the clamp-on CTs 140A-C are small and are very accurateeven though the output currents advantageously range from 0-0.5 mA inthe present embodiment.

As briefly explained above, at each power substation there is generallypower equipment which delivers electrical power. The various types ofpower equipment are usually protected for overload and fault conditionsby monitoring the current in the equipment. A typical method ofmonitoring this current is with a current transformer which steps downthe current in the primary (normally in the range of 100 to 3000 amps)to a secondary current in the range of 5 amps. The secondary current ismonitored with protection equipment, usually involving transducersinstalled in one leg of the secondary of the protection circuit currenttransformer. This generally requires cutting into one leg of thesecondary of the protection circuit if the substation is beingretrofitted. Although this process is time consuming as explained above,it continues to be the conventional method for substation monitoring ofhigh-power, power equipment. Applicant recognized hat this method couldbe greatly simplified.

The clamp-on CTs 140 described connect easily to one leg of thesecondary side of the protection circuit current transformer connectedto each phase of the power equipment. To attach the clamp-on CT 140, aninstaller removes the detachable base plate 214, positions one leg 144A,144B or 144C (FIG. 2) of the protection circuit within the channel 232,and re-attaches the detachable base plate 214. The substation need notbe taken off-line and the protection circuit need not be cut. Thisallows for quick, safe, and efficient installation and repairs.Therefore, the transducers of conventional monitoring systems need notbe installed in the secondary of the protection circuit. Accordingly,installation of the clamp-on CTs 140 of the present inventionsubstantially improves upon the more difficult, time consuming, anddangerous installation of the transducers used in conventional systems.Moreover, even though the CTs 140 are split-core devices which monitorcurrent flowing in a conductor without cutting into the wire, and eventhough the CTs step down the current detected significantly (e.g. to the0-0.5 mA operating range in the present embodiment), the Applicantdesigned the present invention to provide accurate information about thepower flow through the power equipment. This manner in which theaccuracy is maintained is further explained herein.

Once the CTs 140A-C are installed, the legs 144A-C of the protectioncircuit passing through the aperture 232 function as the primary for theCTs 140A-C. Thus, a current, scaled down (by a factor of 10,000 in thepresent embodiment) corresponding to current detected in the protectioncircuit is provided to the secondary of the transformer via theconnectors of the CTs.

A detectable voltage is provided by connecting a resistance (e.g.effectively 2 ohms in the present embodiment) in series with thesecondary of the clamp-on CTs 140A-C (e.g. attaching a resistor betweenthe two connectors). Upon installation, the analog voltage signals fromthe CTs 140A-C are calibrated by using a potentiometer (not shown) tomaintain the 1% repeatable accuracy in the system. The analog voltagesignals from the clamp-on CTs 140A-C are provided to the A/D converter150 which converts the voltages into digital form upon request from theCPU 200. The CPU 200 reads the digitized signals from the conventionaldata bus 203 as previously explained. Because the resistance across theclamp on CT 140A-C is known, the current corresponding to the measuredvoltage is calculated as well understood in the art.

The RTU

The remote terminal unit (RTU) 104 functions as the system controller inthe present embodiment and performs the following primary functions:poll the RDUs 100 for data, transform the AC power equipment voltages tolow voltage AC sense voltages, communicate with a remote computer suchas the host computer 110 and provide the remote computer with the dataobtained from the RDUs 100 upon request.

Advantageously, the RTU is based around a computer motherboard 255. TheRTU 104 hardware comprises a microprocessor based (i.e. an INTEL 80C88)motherboard 255 with a CPU 253, real time clock (not shown), serialcommunications channels each with a dedicated serial interface 254, 262,a memory module 256, and a conventional step-down power converter 260.In the present embodiment, the motherboard 255 advantageously comprisesa conventional C-44 bus 80C88 based controller motherboard as wellunderstood in the art. The serial communications channels utilizeappropriate dedicated serial interfaces 254 and 262. One serialinterface 254 connects the RTU 104 to the RDUs 100 via a sharedconventional RS-485 link. The serial interface 262 is used tocommunicate to either an external modem 265, which in turn connects totelephone lines 264 to communicate with the host 110 as well understoodin the art, or to a radio interface 266, which in turn connects to aradio 267 to communicate with the host. An exemplary radiocommunications link interface advantageously comprises a Metricom PacketRadio Controller which connects to a Metricom transceiver. Those skilledin the art will appreciate that other communications links are alsoappropriate and do not detract from the subject matter regarded asinvention.

In the present embodiment, the memory module 256 advantageouslycomprises an EPROM, which is used for program execution, and a CMOSstatic RAM, which is used for configuration storage [nd is wellunderstood in the art.

The step-down power converter 260 converts AC line voltages on signallines 270, which are usually already stepped down somewhat from either a4 kilovolt or 16 kilovolt (phase to ground) range of the powerequipment, to low voltage (e.g. six-volt) sense voltages. The RTU 104provides these sense signals on signal lines 122 to the RDUs 100-100C,via the daisy chain cable 102, one pair of wires for each sense voltage.The power converter also provides the 24-volt DC power for the RDUs 100on signal lines 120 of the daisy chain cable 102.

An A/D converter (not shown) similar to that of the RDU 100 can also beincluded in the RTU 104 for converting analog data into digital form.

System Firmware

FIG. 5 is a flowchart of operations carried out by each RDU 100. The RTU104 can also perform many of the same functions, but generally leavesthese functions to the RDUs 100-100C. In general, the RDUs 100-100Cacquire sample data representing values for voltage and current for arespective power equipment line, analyze the data, and transmit the datato the RTU 104 upon request. The RTU 104 performs primarily thefunctions of obtaining data from the RDUs 100-100C and for communicatingwith the remote computer 110.

Configuration

During configuration operations, as represented in action block 280, theRDUs 100 read hard configuration data from the DIP switch addressselector 202 connected to a conventional parallel interface 170. The RTU104 has a similar DIP switch (not shown), connected to a conventionalparallel port, for address configuration of the RTU 104. Only fiveswitches from the eight-pin DIP 202 are allocated for address selection.Upon start-up and initialization, the RDU 100 reads the address selectedby the five switches connected to the parallel port 170 and stores theaddress in the CMOS portion of the memory 160 of the RDU 100. The RTU104 executes the same function with its address selector. Thereafter,during normal operations, the RDUs 100 and the RTU 104 read theircorresponding addresses from the memories when a communication requestis made to, or a transfer is executed by, these devices. An RDU 100 orRTU 104 will only respond to serial communications requests withaddresses that match the selected addresses for that RDU 100.

The other three switches in the eight-switch DIP 202 provideconfiguration information about the type of power equipment line whichis monitored by the RDU 100. For instance three-phase or single phase,clockwise or counterclockwise, and phase-to-neutral or phase-to-phasemonitoring.

In the present embodiment, the three switches (switch 8, switch 7, andswitch 6) not used for address selection are defined as shown in Table 1to configure the corresponding RDU 100 for the type of monitoringinvolved:

                  TABLE 1                                                         ______________________________________                                        SWITCH SELECTION                                                              S8     S7      S6           DESCRIPTION                                       ______________________________________                                        0      0       0      (0)   Undefined (invalid)                               0      0       1      (1)   3 phase, CW & CCW, P-N                            0      1       0      (2)   3 phase, CW, P-P                                  0      1       1      (3)   3 phase, CCW, P-P                                 1      0       0      (4)   1 phase, CW, P-N                                  1      0       1      (5)   1 phase, CW, P-P                                  1      1       0      (6)   1 phase, CCW, P-N                                 1      1       1      (7)   1 phase, CCW, P-P                                 ______________________________________                                         where:                                                                        CW = ABC clockwise; CCW = ABC counterclockwise                                P-P = phaseto-phase; P-N = phaseto-neutral                               

The RDU 100 reads and stores the value of these three switches in theCMOS portion of the memory 160, and uses this configuration informationduring subsequent operations as later explained.

The RDUs 100 also accept optional data downloaded from the RTU 104 andthe host 110 to configure the RDUs 100. For instance, the RDUs 100 canreceive a unique address from the RTU 104 which the RDU 100 will useinstead of the switch-selected address. The RTU 104 may also receive aunique address from the host computer 110 to which it will respond tothe exclusion of the switch-selected address of the RTU 104.

The RDU 100 can also receive correction offset values for phasedifferences computed for each current-voltage pair as explained herein.These offsets correct for system bias or other factors specific to agiven RDU 100.

Finally, because the RDU 100 scales all data it collects intoengineering units, it receives scaling factors for this operation whichare downloaded from the host 110 via the RTU 104. Again, the RDU 100stores all this configuration information in the CMOS portion of thememory 160 for further reference during subsequent operations.

Data Collection and Analysis by the RDU

Once configuration of the RDUs 100 and the RTU 104 is complete, the RDUs100 begin data collection and analysis.

In the present embodiment the RDU initiates data collectionapproximately every three seconds. Data sampling is represented inaction block 281 of the flow chart of FIG. 5. During data sampling, theA/D converter 150 samples the low voltage AC sense signals on signallines 123 and signals from the clamp-on CTs 140A-C at a frequencysufficient to determine the phase angle between the voltage and thecurrent waveforms. The A/D also samples two analog DC reference signalson lines a DC CAL.0 signal line 151 and a DC CAL.1 signal line 153connected to two channels of the A/D converter 150. In the presentembodiment, the A/D converter 150 samples the six-volt sense signals andthe voltages from the clamp-on CTs 140A-C at a rate of approximately2400 times each second, but only samples the waveforms at this rate for0.25 seconds (15 cycles of 60 Hz voltage and current signals). Moreover,the two channels accepting signals representing the current and voltagesine waves from a respective power equipment line are sampled in tandem.Thus, each channel is only sampled at a rate of approximately 1200samples per second.

The samples are later corrected for the 1/2400 second delay between thesample points of voltage sine wave and the sample points of the currentsine wave. This sampling rate provides sufficient information for theRDU 100 to determine the magnitude of the voltage and the current, andalso to calculate the phase angle between the voltage and current in thepower equipment.

Analog-to-Digital Data Processing

Typically, the data sampled from the A/D represents real time signalsfrom AC sine waves for current and voltage. Current and voltage sinewaves from the same power line are related by the phase relationshipbetween these sine waves. The determination of an accurate phaserelationship, as represented in action block 282, involves a number ofsteps according to the present invention, as further represented in theflow chart of FIG. 5B. The sample data is first transformed to obtain atransformed time scaled sample distribution with samples points spacedat appropriate intervals to represent a whole number of cycles becausethe raw sample points will not necessarily obtain the precise maximums,minimums, and zero crossings for the sampled sine waves. Then, becauseany two A/D channels sampled in tandem are not sampled at precisely thesame instant, the samples are corrected for the 1/2400 second differencein the sample point. The "absolute phase" of the individual sine wavesis next determined. (For purposes of this description, absolute phase ofa sampled sine wave is defined as the instantaneous phase at the momentwhen the very first sample was taken of the wave during any 0.25 secondpacket of data collection. Finally, the relative phase between twosampled sine waves is determined. This process is further explainedbelow.

In the present embodiment, after collecting 15 cycles of raw data, theRDU 100 transforms this data into transformed sine wave distributionswith a number of sample points equal to an integer (I) multiple of thefrequency as represented in action block 300 (FIG. 5A). To transform thedata, an imaginary clock is defined which ticks at a rate of 100 timesfor each sample taken from a single channel. The number of ticks persecond is unimportant as long as the imaginary clock ticks 100 times persample from a selected channel. For illustration purposes, the imaginaryclock ticks at approximately 120,000 ticks per second. This is becausethe RDU 100 samples two channels in tandem. Thus, either one of thechannels is only sampled at a rate of 1200 samples/second. (1200samples/second * 100 ticks/sample=120,000 ticks/second).

Each sample point of raw data from a single channel is assigned a"sample time" corresponding to the elapsed ticks of the imaginary clockreferenced from the first raw sample which has a sample time equal zero.

Once the data points are collected and have corresponding sample time(expressed in ticks of the imaginary clock), the RDU 100 determines thecycle time of the sine wave sampled from each channel, expressed inticks of the imaginary clock. In order to find the cycle time, the RDU100 searches for a starting point for the cycle time among the first fewsample points. The starting point for the cycle is taken as the firstsample point with a value which falls between two smaller points on oneside of the sample point and two larger points on the other side.(Whether the slope of the sine wave is positive or negative at theselected point is noted for later use). This assures that the startingpoint will not be too near either a maximum or a minimum of the sinewave. The starting sample point is marked with "time mark 0."

Next, the RDU 100 scans forward through the samples to identify samplepoints equivalent to the starting point. For instance, if the sine wavemagnitude was increasing at the starting point, then equivalent samplepoints are all points which are preceded by a point with a smaller valuethan the starting point, followed immediately by a point that is equalto or larger than the starting point. If the value of the second pointis exactly equal to the value of the starting point, then this pointprovides a sample point for a cycle-time "time mark n" (e.g., the firstoccurrence receives a "time mark 1," the second a "time mark 2," etc).When the second sample point is not exactly equal to the value of thestart point (time mark 0), then the RDU 100 interpolates between thefirst sample point smaller than the starting point and the second samplepoint larger than the starting point to obtain a sample point with avalue exactly equal to the starting point. Then the time for theinterpolated sample is recorded as time mark n.

The difference in time between each successive pair of time marksprovides individual estimates of the cycle times for each cycle of thesine wave for the corresponding channel of the A/D converter 150. Thecycle times between each time mark are then averaged (referred to as"cycle-time" for further discussion herein). As a safeguard againstspurious noise, the individual cycle time estimates are compared tocycle-time (the average), and any sample that differs more than fivepercent is discarded as invalid. Then, the RDU 100 calculates a newaverage cycle-time, excluding the discarded individual cycle timeestimates. This contributes to maintaining the accuracy in the system

Once the cycle-time is determined, the RDU 100 transforms the raw datainto a distribution with exactly `S` (a whole number) samples per cycle.Dividing cycle-time by S provides the number of ticks, `I`, which elapsebetween successive transformed sample points.

The first sample point is defined as "sample time 0." The second samplepoint is a transformed sample point with a sample time of I (integermultiple of cycle-time). If a raw sample has a sample time exactly equalto I, then this raw sample point is used, otherwise the RDU 100interpolates to obtain a sample point corresponding to sample time I.This process is repeated for sample times 2I, 3I, . . ., SI. The endresult is a transformed sample distribution which contains samplesspaced at appropriate intervals to represent exactly a whole number ofcycles, each with S sample points per cycle. This transformeddistribution provides enhanced accuracy for the data sampled in order tomaintain the 1% repeatable accuracy desirable in the present system.

Absolute Phase Determination. The absolute phase for the sine wave isthen determined as described below and represented in action blocks 301(FIG. 5B).

To determine the absolute phase of a sampled sine wave, the RDU 100first calculates the midline of the sine wave. The midline is found bycalculating the mean of the transformed sample distribution. (The meanwill provide a more accurate midline of the sine wave if thedistribution is a whole number of cycles as provided by the transformeddistribution). Once the midline of the sine wave is determined, the RDU100 compares the individual sample points to the midline. Whenever, twosuccessive samples are found where one sample is smaller than themidline, followed immediately by a sample point exactly equal to themidline, the sample time of the point equal to the midline is taken asthe start of a new cycle. If the second point is greater than themidline, then a sample point between the two points is interpolated toestimate a point equal to the midline. The starting time for each newcycle, referred to as that cycle's "phase-zero-time," is determined inticks of the imaginary clock in reference to the first sample taken.

The number of ticks between phase-zero-times for each successive cycleprovides another estimate for cycle-time as defined above. If any of theindividual differences between phase-zero-times for successive cyclesdiffer from cycle-time by more than five percent, the entiredistribution is discarded as invalid.

If the distribution is not invalid, the phase-zero-time for each cycleis divided, with an integer division operation, by the number of ticksper cycle (cycle-time). The remainder of the division operations areaveraged to obtain an average estimate of the absolute phase of the sinewave referenced from the instant of taking the first sample.

Discarding the invalid distributions and averaging the divisionoperations again contributes to maintaining the 1% accuracy desirable inthe present system.

Relative Phase Determination. In the present embodiment, the relativephase between samples from two channels accepting data from the samephase of the power line is next determined as represented in actionblocks 302, 303 and 304 (FIG. 5B). Because the samples from the channelscome 50 ticks apart, one sample distribution is corrected for thisoffset as represented in action block 302. This correction results inthe transformed distributions absolute phase being synchronized. Thecurrent is generally sampled after the voltage. Thus, 50 ticks aresubtracted from the absolute phase of the current distribution. Thisprovides an absolute phase estimate for the current distribution at thesame instant when the first voltage sample was taken. If subtracting 50ticks results in a negative number, indicating that the current sinewave has started a new cycle sometime in the 50-tick interval, then thecycle-time for the current wave is added to the negative absolute phasevalue. This results in a value of ticks after the start of the previouscycle.

The RDU 100 determines the relative phase by subtracting the absolutephase of the voltage from the absolute phase of the current, asrepresented in action block 303. If this value is negative, thencycle-time is added to the negative value.

The RDU 100 also converts the relative phase (now expressed in ticks)into degrees, as represented in action block 304. Because the ticks percycle (cycle-time) is known, the equations is as follows: relative phasein degrees= ##EQU1## A selected constant, depending on the type of powerline and the phase monitored, is added to the result to obtain phasereadings which indicate by how many degrees the current sine wave lagsthe voltage sine wave. The appropriate constants are provided in Table 2below. The value obtained is also corrected by adding any configurationoffsets downloaded from the RTU 104 to the RDU 100 during configurationoperations as described above.

                  TABLE 2                                                         ______________________________________                                        DESCRIPTION    A PHASE   B PHASE   C PHASE                                    ______________________________________                                        3 PHASE, CW & CCW,                                                                           0          0         0                                         P-N                                                                           3 PHASE, CW, P-P                                                                             30         30        30                                        3 PHASE, CCW, P-P                                                                            330       330       330                                        1 PHASE, CW, P-N                                                                             0         120       330                                        1 PHASE, CW, P-P                                                                             30        150       270                                        1 PHASE, CCW, P-N                                                                            0         240       120                                        1 PHASE, CCW P-P                                                                             330       210        90                                        ______________________________________                                         CW = ABC clockwise; CCW = ABC counterclockwise                                P-N = phaseto-neutral; P-P = phaseto-phase                               

Computing Unscaled Root Mean Squared Valued

The RDU 100, having read the digitized values of the low-voltage sensesignals and the digitized values of signals representing current fromthe clamp-on CTs 140 from the A/D converter 150, and having determinedthe relative phase angle between the voltage and current of thetransformed synchronized distributions, calculates values correspondingto watts (W), volt-amperes (VA), volt-amperes-reactive (VAR) and thepower factor (PF), as represented in action block 284. If an RDU 100 ismonitoring a three-phase power equipment line, then it also calculatesthree-phase power and the neutral current, as represented in actionblock 286 (FIG. 5A).

The first step in these calculations is to find the root mean square(RMS) values of the voltage and current sine waves as represented inaction block 283. The computationally efficient method of calculatingthe RMS values is to sum the square of each sample value and divide bythe number of samples, subtract the square of the sample mean, and takethe square root as follows: ##EQU2## This provide RMS values for thedigitized representations of the sampled sine waves.

Calibration and Scaling of the RMS values

However, because the voltage sense signals, and the signals from theclamp-on CTs 140 are scaled down substantially from actual line voltagesand currents, and because electronics and inaccuracies in the systemintroduce bias, each RDU 100 utilizes scaling and calibrationinformation to scale the voltage and current calculations to representactual substation power line values.

The calibration to eliminate system bias introduced into the data byelectronics and error is compensated by connecting precise DC analogsignals to two of the A/D converter 150 channels. These signals arecarried on the DC CAL.0 signal line 151 and the DC CAL.1 signal line 153as depicted in FIG. 2. One channel is set to a level representing the0-volt value by connecting the DC CAL.0 input signal line 151 to ground.The other channel is set to a level representing half the maximumpossible line value. In a preferred embodiment, a calibration circuitsuitable for setting the half level reference is a Motorolla MC-1403U.However, other calibration circuits are also suitable as well known inthe art. The calibration is further enhanced to prevent the possibilityof a spike during a calibration value sample by calculating the mean ofa series of calibration samples. The calibration factor (CF) is thendetermined by the following equation:

    CF=(RHS--RO)/(CHS--C)

where:

RHS=raw scale sample

RO=raw minimum sample

CHS=mean half scale value

CO=mean minimum sample value

Once the CSF is determined, the raw RMS values are multiplied by thiscalibration factor to correct for bias in the system.

However, the raw RMS values still do not represent physical values foramperes or volts. Therefore, a respective scaling factor is applied tothe voltage and amperes calibrated RMS values. In the presentembodiment, because the current ranges in the protection circuit from0-5 amps, the scaling factor for current is 5.000 (i.e., the RMS currentvalue is scaled to an integer value ranging from 0-5000, where 5000represents 5.0 amps). Because the voltages provided to the RTU on signallines 270 generally range from 0-150 volts in the present embodiment,the voltage scaling factor is 150.00 (i.e., the RMS voltages are scaledto an integer value ranging from 0-15000, where 15000 represents 150.00volts).

Computing Watts, Vars, and Power Factor

After the sample data is calibrated and scaled, the RDU 100 calculatesvolt-amps by multiplying the RMS voltage by the RMS current. The wattsand vars are computed by multiplying volt amps by the cosine or the sineof the relative phase angle respectively. The power factor is computedas the cosine of the relative phase angle between the current andvoltage. Power factor is expressed as an integer value in the range of+/-10000, where 10000 represents 1.0000. These calculations arerepresented in action block 284.

If the system is monitoring a three-phase equipment line (represented indecision block 285), the three-phase values are also calculated, asrepresented in action block 286, as follows:

Three phase volts=average of volts for all three phases.

Three-phase amps=sum of amps for the three individual phases

Three-phase volt amps=sum of volt amps for the three individual phases

Three-phase watts=sum of watts for the three individual phases.

Three-phase vars=sum of vars for the three individual phases.

These calculations are well understood in the art.

The RDUs 100 store the data acquired and the calculation results in itsmemory 160, as represented in action block 287.

Once the RDUs 100 have stored the data acquired, the RDUs determinewhether any control functions are necessary, as represented in decisionblock 288. A control function would normally be carried out utilizingthe digital I/O interface 190 of the RDU 100. In one embodiment, thedigital interface 190 has 12 digital inputs and 12 digital outputs. Anexemplary use for the digital inputs is to monitor circuit breakerstatus in the substation. Two digital inputs can be used for eachcircuit breaker. One digital input to indicate that a selected circuitbreaker (not shown) is open and one input to indicate that the selectedcircuit breaker is closed. The digital outputs of the digital interface190 can be used to perform other control functions as may be neededthroughout the substation. The RTU 104 has similar capabilities.

If a control function is necessary, then the RDU 100 will perform thatcontrol function, as represented in action block 289. If no controlfunctions are currently requesting service from the RDU 100, the RDU 100executes any serial communications commands, as represented in actionblock 290, if the RTU 104 has requested information from the RDU 100.

Once all of these functions are carried out by the RDU 100, the RDU 100will wait until the 3-second sampling period has expired, as representedin decision block 291. As soon as the 3-second sampling period hasexpired, the RDU 100 will return to action block 281 and collect another0.25 seconds of data and repeat the sequence of data acquisition,analysis and executing other operations.

Interrupt Driven Tasks

The data collection and analysis routine just described occurs under RDU100 control every 3 seconds in the present embodiment. The RDU 100 alsoaccepts interrupt-driven tasks which occur asynchronously to the maintasking as explained above.

For instance, the CPU clock is configured to interrupt the CPU 200 every100 milliseconds. Upon this interrupt, the time of day, day of week anddate are read from the real time clock/calendar and stored into the mainmemory of the RDU 100. The serial I/O interface 172 provides anotherinterrupt. Whenever the RDU 100 receives or transmits a character viaits serial I/O interface 172, an interrupt is generated. This interruptcauses the next character to be sent or stored in memory 160 by the CPU200. At the end of the transmission or reception of data, the serialinterface sets a flag for the CPU 200 indicating that the transmitbuffer has been sent or that a receive buffer is available. This serialinterface protocol is well understood in the art.

Communications Capability

Advantageously, the RDU 100 communicates with the RTU 104 via a serialcommunications multidrop interface well understood in the art. Datatransfers are carried out using eight-bit protocol as well understood inthe art. All RDUs 100 connected to one RTU 104 communicate over thislocal area network (LAN) where communications are multidropped over thesame wire. Thus, the RTU 104 transmits and receives, and all the RDUs100 transmit and receive over one pair of wires. The resulting system isa peer-to-peer communications structure as well understood in the art.The RDUs 100 collect and analyze large amounts of data as explainedabove, which they transmit to the RTU 104 upon request.

In the present embodiment, communications between the RDUs 100 and theRTU 104, and between the RTU 104 and the host 110 advantageously adhereto the NetCom protocol proprietary to the Metricom Corporation. However,other protocols well understood in the art for serial communications ina LAN are also appropriate for use with the system and do not detractfrom the subject matter regarded as invention.

RTU Specific Firmware

As depicted in the flow chart of FIG. 6, the RTU 104 is programmed toperform a number of functions that the RDUs 100 do not generallyperform. The RTU 104 polls the RDUs 100, as represented in action block310, to obtain the data collected and processed by the RDUs 100 asexplained above, and stores this data for each RDU 100 in a database, asrepresented in action block 311. The RTU 104 provides this data to thehost 110 upon request via the communications link 106 (FIG. 1), asrepresented in decision block 312 and action block 313.

Remote RDU Configuration

The present invention can also be implemented without an RTU 104 at eachsubstation location, as illustrated in FIGS. 7 and 7A. The RDUs 100-100Bstill form a daisy chained network, and a local step-down powerconverter/supply 350 accepts the sense voltages (e.g. 120 VAC) from thepower equipment on lines 272 and converts these to low voltage (e.g.six-volt) AC sense voltages accepted by RDUs 100. The local power supply350 accepts station power on line 352 and provides the 24-volt DC powerfor the RDU 100 power supply 130 (FIG. 2). The data collected andcalculated by the RDUs 100, 100A and 100B (FIG. 7A) is transmitted to aremote RTU 104 via a radio transmitter 354, or other communicationslink. The RTU 104 then receives the signals from the remote RDUs 100 viathe radio 356. The RTU 104 may also monitor other RDU 100 deviceslocally, as shown in FIG. 7 as RDU 100C and 100D.

Although the preferred embodiment of the present invention has beendescribed and illustrated above, those skilled in the art willappreciate that various changes and modifications to the presentinvention do not depart from the spirit of the invention. Accordingly,the scope of the present invention is limited only by the scope of thefollowing appended claims.

What is claimed is:
 1. A substation monitoring system wherein thesubstation distributes power through power equipment carrying a voltagewaveform and a current waveform, wherein the power equipment also hasassociated protection circuits carrying a current waveform which isstepped down from, but proportional to, the current waveform in thepower equipment, said system comprising:at least one system controller;a power converter which steps down said power equipment voltagewaveform; a high-accuracy, split-core current transformer permanently,yet detachably mounted on one leg of said protection circuit, saidcurrent transformer providing a stepped down current waveform, steppeddown from, but proportional to, the current waveform in the powerequipment; a sampler which accepts the stepped down current waveformfrom said current transformer and converts the stepped down currentwaveform into a digital representation of said current waveform, andwhich accepts the stepped-down power equipment voltage waveform andconverts the voltage waveform to a digital representation of saidvoltage waveform; at least one microcontroller based data unit incommunication with said system controller, wherein said data unit iscoupled to the sampler and accepts the digital representations of thevoltage and current waveforms from said sampler and determines from thedigital representations of the voltage and current waveforms, a relativephase angle between the sampled current waveform and the sampled voltagewaveform, and wherein the data unit further utilizes the digitalrepresentations of the voltage and current waveforms to calculate thepower, power factor, and volt amperes reactive, distributed by saidpower equipment; and a communications link which sends said calculationsto a remote computer.
 2. The substation monitoring system of claim 1,wherein current in said protection circuit is in the range of 0-5 Amps,and the stepped down current waveform from said split-core currenttransformer is in the range of 0-0.5 mA.
 3. The substation monitoringsystem of claim 2, wherein the split-core current transformer iscalibrated upon installation such that is has a repeatable accuracy of1% or better in the current range during system operation.
 4. A methodof monitoring substation power equipment carrying a voltage waveform anda current waveform, wherein the power equipment also has associatedprotection circuits carrying a current waveform which is stepped downfrom, but proportional to, the current waveform in said power equipment,said method comprising:providing at least one system controller;providing at least one data acquisition controller in communication withsaid system controller; stepping down said power equipment voltagewaveform; permanently, yet detachably mounted a split-core currenttransformer on one leg of said protection circuit, said currenttransformer providing a current waveform, stepped down from, butproportional to, the current waveform in said power equipment; samplingthe current waveform provided by said current transformer and convertingthe current waveform into a digital representation of the currentwaveform for further processing by said system controller and said dataacquisition controller; sampling said stepped-down power equipmentvoltage waveform and converting said voltage waveform to a digitalrepresentation of the voltage waveform; and determining a relative phaseangle between the sampled current waveform and the sampled voltagewaveform by utilizing the digital representation of the voltage andcurrent waveforms; calculating the power, power factor and volt amperesreactive distributed by said power equipment by using the sampleddigital representations of the voltage and current waveforms; andtransmitting the calculations to a remote computer.
 5. A method ofmonitoring substation power equipment carrying a voltage waveform and acurrent waveform, wherein the power equipment also has associatedprotection circuits carrying a current waveform which is stepped downfrom, but proportional to, the current waveform in said power equipment,wherein the voltage and current waveforms are alternating current sinewaves said method comprising:providing a at least one system controller;providing at least one intelligent data unit in communication with saidsystem controller; stepping down the power equipment voltage waveform;permanently, yet detachably mounting a high-accuracy, split-core currenttransformer on at leas one leg of said protection circuit, said currenttransformer providing a current waveform stepped down from, butproportional to, the current waveform in said power equipment; samplingthe current waveform provided by said current transformer and convertingthe current waveform into a digital representation of the currentwaveform for further processing by said data unit and said systemcontroller; sampling said stepped-down power equipment voltage waveformand converting said voltage waveform to a digital representation of thepower equipment voltage waveform; and determining a relative phase anglebetween the sampled current waveform and the sampled voltage waveformsine waves by utilizing the digital representations of the voltage andcurrent waveforms.
 6. The method of monitoring of claim 5, wherein saidstep of detachably mounting comprises the steps of:removing a detachablebase plate of said split-core current transformer; positioning said oneleg of said protection circuit within the split-core currenttransformer; and re-attaching the detachable base plate.
 7. The methodof monitoring of claim 5, wherein said system controller communicateswith a remote computer.
 8. The method of monitoring of claim 5, furthercomprising the steps of:calculating the power, volt amperes, powerfactor, and volt amperes reactive, associated with said power equipmentby utilizing the digital representations of the voltage and currentwaveforms; and transmitting said calculations to a remote computer.
 9. Amethod of monitoring substation power equipment carrying a voltage and acurrent in the form of sine waves, wherein the power equipment also hasassociated protection circuits carrying a current in the form of sinewaves which is stepped down from, but proportional to, the currentflowing in said power equipment, said method comprising the stepsof:stepping down the power equipment voltage; stepping down theprotection circuit current with a split-core current transformer bydetachably mounting the split-core current transformer on a leg of theprotection circuit, such that a current provided from the split-coretransformer is proportional to the current flowing in the powerequipment; sampling with a sampler the current provided by said currenttransformer and converting the current into a digital representationwith a single converter, wherein the sampling and converting of thecurrent provides a first plurality of raw sample points representativeof the current sine waves in said power equipment; sampling with saidsampler said stepped-down power equipment voltage and converting saidvoltage to a digital representation of the voltage with said singleconverter, wherein the sampling and converting of the voltage provides asecond plurality of raw sample points representative of the voltage sinewaves in said power equipment said second plurality not beingsynchronized in time with the first plurality of raw sample points;assigning corresponding time clicks for each of the first plurality andthe second plurality of raw sample points; and transforming the firstand the second plurality of raw sample points into a first transformedsynchronized distribution and a second transformed synchronizeddistribution, wherein the first and second transformed distributionscomprises corresponding synchronized sample points which form arepresentation of the voltage and current sine waves of said powerequipment.
 10. The method of monitoring power equipment of claim 9, themethod further comprising the steps of:calculating a first mean of thefirst transformed distribution and a second means of the secondtransformed distribution; determining the time clicks for points in thefirst transformed distribution which equal the first mean; determiningthe time clicks for points in the second transformed distribution whichequal the second mean; averaging the difference in time clicks betweenconsecutive points in the first transformed distribution which equal thefirst mean to determine an average cycle time for said first transformeddistribution; and averaging the difference in time clicks betweenconsecutive points in the second transformed distribution which equalthe second mean to determine an average cycle time for said secondtransformed distribution.
 11. The method of monitoring substation powerof claim 10, the method further comprising the step of:calculating thedifference between the average cycle time for said first distributionand the average cycle time for said second distribution to determine arelative phase time between said first and said second transformeddistributions.
 12. The method of monitoring substation power of claim11, the method further comprising the steps of:calculating the rootmeans squared voltage and the root means squared current for said powerequipment from the first and second transformed distributions; andcalculating a power factor for said power equipment corresponding to therelative phase between the first and the second transformeddistributions.
 13. The method of monitoring substation power of claim 9,the method further comprising the steps of:determining an average cycletime for said first transformed distribution; determining an averagecycle time for said second transformed distribution; and determining arelative phase time between said first and said second transformeddistributions.
 14. The method of monitoring substation power of claim13, the method further comprising the steps of:calculating the rootmeans squared voltage and the root mean squared current of the powerequipment from the first and second transformed distributions; andcalculating a power factor for the power equipment corresponding to therelative phase between the first and the second transformeddistributions.
 15. A method of monitoring substation power distributedby power equipment carrying a voltage and a current in the form of sinewaves, wherein the power equipment also has associated protectioncircuits carrying a current which is stepped down from, but proportionalto, the current flowing in said power equipment, said method comprisingthe steps of:stepping down the power equipment voltage; stepping downthe protection circuit current with a split-core current transformer bydetachably mounting the split-core current transformer on a leg of saidprotection circuit, such that a current provided from the split-coretransformer is proportional to the current flowing in the powerequipment; sampling a representation of the current provided by saidcurrent transformer and converting said representation into digital formwith a converter, wherein the sampling and converting of therepresentation of the current provides a first plurality of raw samplepoints representative of the current flowing in said power equipment;sampling the stepped-down power equipment voltage and converting saidvoltage to digital form with said converter, wherein the sampling andconverting of the voltage provides a second plurality of raw samplepoints representative of the voltage in said power equipment, said firstplurality of raw sample points not being synchronized in time with saidsecond plurality of raw sample points; and transforming the first andthe second plurality of raw sample points into a first transformedsynchronized distribution and a second transformed synchronizeddistribution wherein the first transformed distribution comprises afirst plurality of data points and the second transformed distributioncomprises a second plurality of data points, said first plurality ofdata points being synchronized in time to the second plurality of datapoints.
 16. A monitoring system for use with power equipment carryingrelated voltage and current sine waves, the system comprising:at leastone split-core current transformer permanently, yet detachably mountedon one leg of a protection circuit for the power equipment; a samplerwhich obtains alternate raw sample points of the related voltage andcurrent sine waves and converts the raw sample points to digital form;and data acquisition equipment which accepts the digital raw samplepoints from the sampler, transforms the digital raw sample points intotransformed synchronized distributions having a plurality ofsynchronized digital data points, wherein said transformed distributionsprovide digital representations of the related voltage and current sinewaves; said data acquisition equipment comprising a microcontrollerbased data unit in communication with the sampler, wherein said dataunit is coupled to the sampler and accepts the digital representationsof the voltage and current sine waves, wherein the data unit determinesa relative phase angle between the related voltage and current sinewaves by comparing the digital representations of the related voltageand current sine waves.
 17. A substation monitoring system wherein thesubstation distributes power through power equipment carrying a voltagewaveform and a current waveform, wherein the power equipment also hasassociated protection circuits carrying a current waveform which isstepped down from, but proportional to, the current waveform in thepower equipment, said system comprising:a power converter which stepsdown said power equipment voltage waveform; a split-core currenttransformer permanently, yet detachably mounted on one leg of saidprotection circuit, said current transformer providing a stepped downcurrent waveform, stepped down from, but proportional to, the currentwaveform in the power equipment, said stepped down current waveformbeing in the range of 0-0.5 mA, said split-core current transformerfurther being calibrated within the substation monitoring system to havea repeatable accuracy of 1% or better in the 0-0.5 mA stepped downcurrent waveform range during system operation; a sampler which acceptsthe stepped down current waveform from said current transformer andconverts the stepped down current waveform into a digital representationof said current waveform, and said sampler accepting the stepped downpower equipment voltage waveform and converting the voltage waveform toa digital representation of said voltage waveform; at least onemicrocontroller based data unit coupled to the sampler, said data unitaccepting the digital representations of the voltage and currentwaveforms from said sampler and determining from the digitalrepresentations of the voltage and current waveforms, a relative phaseangle between the sampled current waveform and the sampled voltagewaveform, and wherein the data unit further utilizes the digitalrepresentations of the voltage and current waveforms to calculate thepower, power factor, and volt amperes reactive, distributed by saidpower equipment; and a communications link which sends said calculationsto a remote computer.
 18. A substation monitoring system wherein thesubstation distributes power through power equipment carrying a voltagewaveform and a current waveform, wherein the power equipment also hasassociated protection circuits carrying a current waveform which isstepped down from, but proportional to, the current waveform in thepower equipment, said system comprising:a power converter which stepsdown said power equipment voltage waveform; a split-core currenttransformer detachably mounted on one leg of said protection circuit,said current transformer providing a stepped down current waveform,stepped down from, but proportional to, the current waveform in thepower equipment; a sampler which accepts the stepped down currentwaveform from said current transformer and converts the stepped downcurrent waveform into a digital representation of said current waveform,said sampler further accepting the stepped down power equipment voltagewaveform and converting the voltage waveform to a digital representationof said voltage waveform; and at least one microcontroller based dataunit coupled to the sampler, said data unit accepting the digitalrepresentations of the voltage and current waveforms from said samplerand determining from the digital representations of the voltage andcurrent waveforms, a relative phase angle between the sampled currentwaveform and the sampled voltage waveform, and wherein the data unitfurther utilizes the digital representations of the voltage and currentwaveforms to calculate the power, power factor, and volt amperesreactive, distributed by said power equipment.